In oil and gas wells, after the production liners are installed, a completion string is installed into the well to produce well fluids. This completion string may contain a variety of tooling required to produce the wells fluids. In thermal wells, specialized tooling is required to allow for thermal expansion.
In thermal applications where steam is injected into the formation to loosen and fluidize well fluids, the tooling placed in the well require special seals to withstand the injection pressures and temperatures of steam, which are in the range of 350° C. at 2500 PSI. Special tooling required for steaming typically includes a bottom packer, sliding sleeve, expansion joints as well as pumps and the completion string connected to the surface. Seals found in the bottom packer, sliding sleeve, and expansion joints are all known to have seal failures over time, resulting in a loss of quality and quantity of steam being delivered to the formation, which in turn also lead to lowered production rates.
During steaming of the well, the steam can be delivered from surface either through the completion string or through an intermediate casing to the production liner in the open hole below the intermediate casing. In either procedure, the completion string is subject to thermal changes. Most often, steam is delivered through the completion string, which protects the intermediate casing from thermal expansion, as well as surface equipment such as the well head. During this process, the sliding sleeve is in a closed position which isolates the completion string from the intermediate casing. During steaming, all seals are subject to steam temperatures and pressures. As the completion string grows under thermal expansion, the expansion joints close. During production, the sliding sleeve is operated in an open position to connect the completion string and to the intermediate casing annulus. This is done to vent off any gases that could enter from the pump side to the intermediate casing side. As the well is produced and temperatures and pressures slowly decrease, the expansion joint begins to open again. All these seals, especially the expansion joint seals, are subject to failure, affecting wellhead temperatures and cemented casing expansions. This can result in casing and wellhead failures.
The bottom packer contains seals on its outside diameter which seal to the intermediate casing and seals on its inside diameter to seal to the completion string. The bottom packer is run in the hole to a pre-determined depth and the seals are set by compressing them to force the seals in an outward position. The compression continues until the outside diameter seals of the packer, are forced against the inside diameter of the intermediate casing. The bottom packers usually consists of a ratchet ring, which has a one direction movement. As the seals are compressed, the ratchet ring locks, preventing the seals from returning to their original position, thus creating the seal.
Known sliding sleeves consist of a tube within a tube. The outer tube or sleeve has holes through its wall. The inner tube or sleeve consists of two sets of seals to seal against either side of the holes on the outer sleeve. Movement of the inner sleeve will open the holes and allow communication between the completion string and the intermediate casing annulus.
Expansion joints typically used in the art consist of an inner sleeve and outer sleeve and a set of seals. The inner sleeve is connected to the completion string above and the outer sleeve is connected to the completion string below. As the completion string expands or contracts, movement of the expansion joint is meant to relieve any stresses the completion string would of otherwise be subject to.
In most existing tools, the seals are of elastomeric or graphite material. As such, it is not uncommon for them to wash, become brittle from the heat and break. Such seals typically do not have any memory and do not return to their original shape after being stressed.
The intermediate casing itself can also aid in creating a poor seal. The intermediate casing may not always have a uniform diameter to seal to. API specifications dictate that the casing wall thickness must be within +/−12% of the total wall thickness, which allows for a great deal of variance. Typically, two types of casing are made; a seamless pipe and an ERW (electric resistivity weld) pipe. The seamless pipe is manufactured from a solid bar stock and has no seam, but the wall thickness will vary within the 12% allowable through the entire length of the pipe. The ERW pipe has consistent wall thickness but contains a weld seam that runs the entire length of the pipes inside diameter. In both cases, either the weld seam or the wall thickness variance can affect the seal performance of the bottom packer.
It is therefore desirable to develop a completion device that can ensure better sealing against the intermediate casing and production liner, and also reduce seal failure.